An oil reservoir consists of a subterranean formation with small interconnected pores filled with hydrocarbon liquid, gas, and water, usually at an elevated pressure. The hydrocarbon liquid phase at reservoir temperature and pressure, hereafter termed "oil", includes liquid crude oils and liquid crude oils containing dissolved gases (e.g., methane (CH.sub.4), ethane (C.sub.2 H.sub.6), propane (C.sub.3 H.sub.8), butanes (C.sub.4 H.sub.10), carbon dioxide (CO.sub.2), nitrogen (N.sub.2), and hydrogen sulfide (H.sub.2 S)). The volume fraction of each phase in the porespace is referred to as its "saturation". The formation in which the oil, water, and gas reside consists of strata of varying ability to conduct fluid. The ability of the formation to conduct fluid is measured by its permeability, defined as the ratio of flow rate to the product of applied pressure gradient and fluid viscosity. In high permeability strata, large flow rates can be sustained with relatively low pressure gradients.
Initially, oil is produced from the formation by "primary" production methods that utilize the energy present in the fluids in the formation. For example, primary production can occur by fluid expansion upon a decrease in reservoir pressure.
A high oil saturation usually remains after primary production. At this point, "secondary" recovery techniques are often implemented to recover additional oil. The most common secondary recovery process is a "waterflood" in which large quantities of water are injected into the formation through specified wells to displace oil towards production wells in the vicinity.
In many cases, a high oil saturation is present after the waterflood. This results in part from the high interfacial tension between oil and water. Interfacial tension traps oil in the porespace. "Tertiary" processes are sometimes initiated at this point. The most common commercially applied tertiary recovery process involves injection of substantially non-aqueous fluids to displace oil towards production wells. These non-aqueous fluids are typically high pressure gases or supercritical fluids, which will be referred to as tertiary recovery fluids.
A supercritical state for a fluid exists when the temperature and pressure exceed the fluid's critical density, temperature, and pressure. Below a fluid's critical temperature (T.sub.c) and critical pressure (P.sub.c) the fluid can consist of both a gas and liquid coexisting in a gas-liquid equilibrium. Above and around T.sub.c, and P.sub.c, however, the fluid can exist only in a single phase, known as a supercritical fluid. For example, water has a T.sub.c =374.degree. C. and a P.sub.c =2.21.times.10.sup.7 pascals. Consequently, if water is at a pressure close to its critical pressure, it will become increasingly turbid and milky as the temperature is lowered from a temperature well above to its critical temperature, 374.degree. C., down to its critical temperature. Upon slight additional cooling below the critical temperature the turbidity disappears and two distinct liquid and vapor phases form. A supercritical fluid's properties, such as density, are intermediate between a gaseous and liquid state for the same substance, but are typically more like the corresponding liquid state. Consequently, a supercritical fluid will normally behave more like a liquid than a gas in terms of its physical behavior thereby enhancing its ability to displace and/or extract hydrocarbons from a formation during tertiary recovery.
Fluids commonly used for tertiary recovery are carbon dioxide, nitrogen, methane, and ethane. Such a process is typically referred to as a "gas injection process." When a tertiary injection fluid, also called the injectant, is used in a gas injection process, hydrocarbon components in the oil vaporize into the injectant, modifying the properties of both the oil and injectant so the interfacial tension between them is reduced. The result is that a substantially non-aqueous injectant can reduce the oil saturation below that seen at the end of the waterflood. The physics of this process are described in petroleum engineering texts well known to those skilled in the art.
FIG. 1 illustrates some of the important recovery mechanisms in a gas injection process. It shows a formation with two zones, 102 and 104, with different values of permeability. The higher permeability zone, 104, is completely swept before the lower permeability zone, 102, is completely swept. Once a zone is completely swept with injectant it is typically referred to as a "swept zone," while a zone where the injectant sweep is incomplete is referred to as an "unswept zone." Note that if a zone is said to be "completely swept", it does not mean that all possible oil has been recovered from that zone; rather, it means that the injectant has passed through the entire zone.
Even in zones that are swept, pockets of bypassed oil are present. After a swept zone has been established, continued injection of the injectant, 101, results in extraction of hydrocarbons from residual pockets of oil, 108, remaining after the initial injectant sweep through the higher permeability zone, 104. The result is that a mixture of injectant and extracted hydrocarbons, 105, is produced from the swept zone, 104. Accordingly, in addition to recovering oil by direct displacement, the injectant extracts, by a vaporization process, some of the more volatile hydrocarbon components in the residual oil that remain in the swept zone. This vaporization process is referred to as "extraction". Extraction results in production of hydrocarbons that are initially comprised of more volatile components and progressively become comprised of less volatile components as injectant is recycled and reinjected through the swept zone.
As shown in FIG. 1, a water and hydrocarbon mixture, 103, is produced as injectant, 101, displaces the water and hydrocarbons originally in place, therefore leaving residual pockets of oil, 106, in the lower permeability zone, 102.
Therefore, injectant is used to (1) recover hydrocarbons by displacing hydrocarbons originally in place in the formation and (2) extract hydrocarbon components from bypassed oil remaining after the injectant completes its first sweep in a particular zone. The result is that during gas injection processes, the produced hydrocarbon fluid will be a mixture of displaced and extracted hydrocarbons.
Examples of such displacement/extraction processes on a laboratory scale are given by Stern (1991), and Shyeh-Yung and Stadler (1994), and in field tests by Fox, Simlote, and Beaty (1984). Mathematical models of the oil recovery process also predict this behavior. For example, Huang, Bellamy, and Ohnimus (1986) have described the results of such mathematical modeling.
In practice, the amount of oil recovered from gas injection processes depends on the injectant's effectiveness in (1) displacing the oil's hydrocarbon components, (2) extracting the oil's hydrocarbon components and (3) uniformly contacting the formation. For example, injectant may flow predominantly through high permeability strata and bypass lower permeability portions of the formation altogether. Computer simulation (mathematical modeling) is used to predict how much oil will be recovered, given a description of the formation and an estimate of the remaining oil saturation after gas flooding.
Despite using all available information to design a gas injection process, there are often large uncertainties about the spatial arrangement of the formation's permeability and porosity. This can have a large impact on the performance of the gas injection process. As a result, it is almost always necessary to modify the injection process based on the formation's actual response to injection of the injectant. In operating gas injection projects, gas, water, and oil production rates at individual production wells are used to determine near-term gas injection strategies. Typically, the injectant is redirected away from wells that are producing at an elevated gas-oil ratio (GOR) and towards low GOR wells. Injectant-oil-ratio is also used for this purpose, when appropriate data are available. This is preferred, since injectant-oil-ratio better indicates how much injectant is produced at a given well. McGuire and Stalkup (1992) have described use of this technique at Prudhoe Bay, a field in Alaska currently under hydrocarbon gas flooding. In this case, complex analyses are required to distinguish produced injectant from produced in-place gas. The problem with either of these approaches is that the engineer cannot precisely determine from the available data what fraction of the produced hydrocarbons result from (1) direct displacement of hydrocarbons by the injectant in the lower permeability zone versus (2) extraction of hydrocarbons by the injectant passing through the swept zone. For example, in certain instances, the injectant may extract economically significant quantities of volatile hydrocarbons, including but not limited to methane (C.sub.1), ethane (C.sub.2), propane (C.sub.3), butane (C.sub.4), pentane (C.sub.5), hexane (C.sub.6), heptane (C.sub.7), and/or octane (C.sub.8), from higher permeability zones in the formation completely swept by injectant. Consequently, the continued injection of the tertiary recovery fluid is economically justified. However, as more of the residual volatile components are extracted from the swept zone, the injectant will inefficiently cycle through the zone. As the zone becomes significantly depleted of its residual hydrocarbons it becomes identified as a "thief zone," because the zone (1) takes injectant that could otherwise be used for directly displacing and/or extracting hydrocarbons, and (2) produces relatively small amounts of hydrocarbons.
Thus, there is a need for a method for determining the relative percentage of hydrocarbons produced by (1) injectant extraction from gas-swept zones and (2) injectant displacement of hydrocarbons from unswept zones of a subterranean formation. Such a method would be valuable in helping to manage and maximize the economically efficient use of injectant in field-scale gas injection processes.